Expandable tubular installation systems, methods, and apparatus

ABSTRACT

Systems, apparatus and well intervention methods are described. Tubular member radial expansion apparatus includes a support member having forward and rearward ends; a drive unit and an expansion member disposed on the support member providing force for propelling the expansion member through an expandable tubular and expanding it, the drive unit disposed rearward of the expansion member; front and rear anchors disposed on the support member for engaging the expandable tubular&#39;s ID to provide reaction forces to propagate the expansion member through the expandable tubular, the rear anchor positioned behind the drive unit and providing its reaction force after the front anchor has exited the expandable tubular; a casing lock disposed on the support member and positioned between the expansion member and the front anchor, securing the expandable tubular to the support member during running-in-hole (RIH); and a valve attached to the forward end of the expandable tubular.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims domestic priority benefit under 35 U.S.C. §120from applicants' provisional patent application Ser. No. 61/119,227,filed Dec. 2, 2008, which is incorporated herein by reference.

BACKGROUND INFORMATION

1. Technical Field

The present disclosure relates in general to well construction,completion, remediation, and intervention methods and systems. Moreparticularly, the present disclosure relates to well interventionmethods, systems and apparatus such as open-hole clads, sidetracking,cased-hole patches, and the like, especially those applications in whichthe pre-expanded launchers of standard, bottom-up hydraulic systemscannot pass through wellbore restrictions.

2. Background Art

Current practice for well construction, completion, remediation andother well interventions in openhole and cased-hole use “bottom-up”,radially expandable tubulars, as exemplified by Weatherford's openholeand cased-hole solid-expandable systems known under the tradedesignation MetalSkin®, and featured in their brochure entitled“MetalSkin® Solid Open and Cased Hole Expandable Systems for Open andCased Hole” (2007). These systems are advertised as being designed withrunning clearance in mind to avoid equivalent-circulation-densityproblems and differential sticking. The Weatherford systems includeretrievable collapsible/expandable cones for contingent recovery,metal-to-metal expandable connectors, and elastomeric sealing elements.Also, each system includes a hydraulically assisted backup expansionsystem, which provides an operational contingency. The systems use apositive seal with a circulation valve for more-reliable pressurecontainment than conventional dart seals. These systems are advertisedto provide single-trip efficiency, and four distinct solutions have beendeveloped: openhole-clad, openhole-liner, cased-hole-liner system, andmonobore system. The monobore system is advertised as an openhole linersystem that can extend casing and maintain drift of the expanded casing,where “drift” is assumed to mean the drift diameter, which is the insidediameter that the pipe manufacturer guarantees per specifications. U.S.Pat. Nos. 7,363,984 and 7,172,025 disclose similar bottom-up expandabletubulars, systems, and methods. Published U.S. patent applications2007/0151360 and 2008/0257542 disclose metallurgical and otherproperties of expandable metal tubulars.

Many pre-expanded launchers of standard, bottom-up hydraulic systemscannot pass through wellbore restrictions, do not provide adequateexpansion ratio, and/or do not provide adequate bend radius forinterventions in curved and lateral wellbores. It would be advantageousif well intervention systems, methods and apparatus were available thatallow expansion of tubulars with acceptable expansion ratio and bendradius, as well as allow the launcher and other system components to beretrieved easily from the wellbore should a problem develop downhole.The systems, methods and apparatus of the present disclosure aredirected to these needs.

SUMMARY

In accordance with the present disclosure, wellbore interventionsystems, methods, and apparatus have been developed which reduce orovercome many of the faults of previously known systems, methods andapparatus.

A first aspect of the disclosure is an apparatus for radially expandinga tubular member, the apparatus comprising:

-   -   a) a support member having a forward end and a rearward end;    -   b) a drive unit and an expansion member disposed on the support        member providing force for propelling an expansion member        through and radially expanding an expandable tubular, the drive        unit disposed rearward of the expansion member;    -   c) front and rear anchors disposed on the support member for        engaging the expandable tubular's ID to provide reaction forces        to propagate the expansion member through the expandable        tubular, the rear anchor positioned behind the drive unit and        providing its reaction force after the front anchor has exited        the expandable tubular;    -   d) a casing lock disposed on the support member and positioned        between the expansion member and the front anchor, releasably        securing the expandable tubular to the support member during        running-in-hole (RIH); and    -   e) a valve attached to the forward end of the expandable        tubular.

In certain embodiments, apparatus of this disclosure comprise a flowvalve fluidly connected to the forward end of the support member,providing the ability for circulation during RIH. After deploying to adesired location in the wellbore, the flow rate may be increased to alevel higher than circulation flow rate and then reduced to zero forpermanent valve closure thus sealing the tool. If circulation is notpossible or undesirable, the valve may be replaced with an end cap. Incertain embodiments, the apparatus further comprises a fluid filterfluidly connected to the support member and positioned at the forwardend of the support member, preventing large mud particles from reachingthe tool seals and inner mechanisms. In certain embodiments the valveattached to the forward end of the expandable tubular assists toolrun-in and prevents packing of the expandable tubular with debris. Itmay also be used to divert flow of drilling fluid around the borehole,thus cleaning and carrying debris through the annulus to surface.

Another aspect of this disclosure are systems for radially expandingtubular members, the systems comprising an apparatus of this disclosuresecured to a deployment component such as a coiled tubing (CT) orjointed drill pipe (DP). In an embodiment of this aspect, the inventionis directed to a tubular member radial expansion system comprising:

-   -   a) a deployment component; and    -   b) a tubular member radial expansion apparatus comprising:        -   i) a support member having a forward end and a rearward end;        -   ii) a drive unit and an expansion member disposed on the            support member providing force for propelling the expansion            member through and radially expanding an expandable tubular,            the drive unit disposed rearward of the expansion member;        -   iii) front and rear anchors disposed on the support member            for engaging the expandable tubular's ID to provide reaction            forces to propagate the expansion member through the            expandable tubular, the rear anchor positioned behind the            drive unit and providing its reaction force after the front            anchor has exited the expandable tubular;        -   iv) a casing lock disposed on the support member and            positioned between the expansion member and the front            anchor, releasably securing the expandable tubular to the            support member during running-in-hole; and        -   v) a valve attached to a forward end of the expandable            tubular.

Another aspect of the disclosure are methods of radially expandingtubular members, the method comprising:

-   -   a) deploying an expandable tubular and expansion tool into a        wellbore, the expandable tubular secured to a support member of        the expansion tool, the support member having a forward end and        a rearward end, the rearward end attached to a deployment        component communicating with the surface; and    -   b) performing an intervention operation on the wellbore        comprising using the expansion tool to expand the expandable        tubular and so complete the wellbore,    -   wherein the expansion tool further comprises a drive unit and an        expansion member disposed on the support member providing force        for propelling the expansion member through the expandable        tubular axially from rear to forward and radially expanding the        expandable tubular, the drive unit disposed rearward of the        expansion member; front and rear anchors disposed on the support        member for engaging the expandable tubular's ID to provide        reaction forces to propagate the expansion member through the        expandable tubular, the rear anchor positioned behind the drive        unit and providing its reaction force after the front anchor has        exited the expandable tubular.

Well intervention operations may proceed via coiled tubing or drillpipe, provided the surface arrangement includes a hydraulic workoverunit. The method may be used for interventions such as, but not limitedto, open-hole clads, sidetracking, and cased-hole patches.

The systems, methods and apparatus described herein may provide otherbenefits, and the methods for well intervention are not limited to themethods noted; other methods may be employed.

As used herein the term “expandable tubular” refers to metallic tubularshaving the metallurgical compositions and physical properties describedmore fully herein.

These and other features of the systems, methods, and apparatus of thedisclosure will become more apparent upon review of the briefdescription of the drawings, the detailed description, and the claimsthat follow.

BRIEF DESCRIPTION OF THE DRAWINGS

The manner in which the objectives of this disclosure and otherdesirable characteristics can be obtained is explained in the followingdescription and attached drawings in which:

FIG. 1 is a schematic side elevation view of one system embodimentwithin the present disclosure;

FIG. 2 is a cross-sectional view of a cased vertical wellbore, and anon-cased lateral wellbore branching off the cased wellbore,illustrating certain features of apparatus, systems, and methods of thisdisclosure;

FIG. 3 is a side elevation schematic similar to FIG. 1 illustrating aspecific system within the present disclosure;

FIG. 4 is a cross-sectional view of one embodiment of a fishing toolthat may be used in conjunction with an embodiment of the presentdisclosure;

FIGS. 5 and 6 illustrate logic diagrams of certain aspects of a methodwithin this disclosure;

FIGS. 7A, 7B, and 7C illustrate schematic longitudinal cross sectionalviews of a valve with a piston in the outer body of the valve in a firstposition, a second position, and a third position, respectively; and

FIG. 8 is a photographic representation of an improved upper anchorsub-system used in a trial test.

It is to be noted, however, that the appended drawings are not to scaleand illustrate only typical embodiments of this disclosure, and aretherefore not to be considered limiting of its scope, for the disclosuremay admit to other equally effective embodiments. Identical referencenumerals are used throughout the several views for like or similarelements.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to providean understanding of the disclosed methods and apparatus. However, itwill be understood by those skilled in the art that the methods andapparatus may be practiced without these details and that numerousvariations or modifications from the described embodiments may bepossible.

All phrases, derivations, collocations and multiword expressions usedherein, in particular in the claims that follow, are expressly notlimited to nouns and verbs. It is apparent that meanings are not justexpressed by nouns and verbs or single words. Languages use a variety ofways to express content. The existence of inventive concepts and theways in which these are expressed varies in language-cultures. Forexample, many lexicalized compounds in Germanic languages are oftenexpressed as adjective-noun combinations, noun-preposition-nouncombinations or derivations in Romantic languages. The possibility toinclude phrases, derivations and collocations in the claims is essentialfor high-quality patents, making it possible to reduce expressions totheir conceptual content, and all possible conceptual combinations ofwords that are compatible with such content (either within a language oracross languages) are intended to be included in the used phrases.

As noted above, wellbore intervention systems, methods and apparatusinvolving radially expandable tubulars have been developed which reduceor overcome many of the faults of previously known systems and methods.

The primary features of the systems, methods and apparatus of thepresent disclosure will now be described with reference to FIGS. 1-8, inconjunction with some of the operational details. The same referencenumerals are used throughout to denote the same items in the figures. Inaccordance with the present disclosure, as illustrated in FIG. 1, afirst embodiment 100 of a system for radially expanding a tubular memberis illustrated in side elevation view, and includes an expandabletubular 2 (illustrated in pre-expanded state) having a rearward end 2A,a forward end 2B, and defining an internal diameter (ID) 3; a supportmember 4, which may be a tubular member, and defines one or moreinternal fluid passages (not shown in this view); a conveyance member 6,which may be coiled tubing or drill pipe; a filter 8, a rear anchor 10having one or more engagement means 24 for engaging the ID of expandabletubular 2; a drive unit 12; an expansion member 14, which may be conicalas illustrated or another functional shape, such as spherical; a casinglock 16 having a plurality of engagement means 28 thereon for engagingthe ID of expandable tubular 2; a front anchor 18 having a plurality ofengagement means 26 for engaging the ID of expandable tubular 2; anoptional flow valve 20 having a plurality of flow ports 21, which incertain embodiments may be replaced by an end cap (not illustrated); anda flow valve 22. FIG. 3 provides typical dimensions for one apparatusand system embodiment within this disclosure.

As used herein, the term “expandable tubular” means metallic tubularshaving the metallurgy such as detailed in Table 1, from United Statespublished patent application number 2008/0257542, published Oct. 23,2008, and incorporated herein by reference in its entirety. Note thatthe term “liner” is sometimes used herein, and those of skill in thisart will understand this term is shorthand for “expandable tubular.” Asreported in the '542 application, in one embodiment, a sample of anexpandable tubular member composed of steel Alloy A exhibited a yieldpoint before radial expansion and plastic deformation YP_(BE), of about16%, and a yield point after radial expansion and plastic deformation,YP_(AE), of about 24%. Further, the ductility of the sample of theexpandable tubular member composed of Alloy A also exhibited a higherductility prior to radial expansion and plastic deformation than afterradial expansion and plastic deformation. Many other physical propertiesof steel Alloys A, B, C, and D, such as tensile strength before andafter expansion, anisotropy, strain hardening exponent, carbonequivalent value, and the like, are disclosed in great detail in the'542 published application.

TABLE 1 Metallurgy and Physical Properties of Suitable ExpandableTubulars Steel Element and Percentage By Weight Alloy C Mn P S Si Cu NiCr A 0.065 1.44 0.01 0.002 0.24 0.01 0.01 0.02 B 0.18 1.28 0.017 0.0040.29 0.01 0.01 0.03 C 0.08 0.82 0.006 0.003 0.30 0.16 0.05 0.05 D 0.021.31 0.02 0.001 0.45 — 9.1 18.7

The collection of components other than expandable tubular 2 andconveyance member 6 are sometimes simply referred to herein as anexpansion tool, or simply a tool. It is also noted that apparatus andsystems within the disclosure may be described as modular in nature.

In operation of embodiment 100 of FIG. 1, drive unit 12 provides thenecessary force for propelling expansion member 14 through expandabletubular 2 and expanding it. Front anchor 18 engages expandable tubular 2ID to provide the necessary reaction force to propagate expansion member14 through expandable tubular 2. Rear anchor 10 provides a reactionforce during the last few strokes after front anchor 18 has exitedexpandable tubular 2 and can no longer provide reaction force. Casinglock 16 secures expandable tubular 2 to support member 4 duringRunning-In-Hole (RIH). Flow valve 20 at the forward end of supportmember 4 provides the ability for circulation during RIH. Afterdeploying to a desired location, the flow rate may be increased to alevel higher than circulation flow rate and then reduced to zero forpermanent valve closure thus sealing the support member. If circulationis not possible or undesirable, flow valve 20 may be replaced with anend cap. Flow valve 22 at the forward end of expandable tubular 2 helpstool run-in and prevents packing of expandable tubular 2 with debris. Italso diverts the flow of drilling fluid around the borehole thuscleaning and carrying debris through the annulus to surface. Fluidfilter 8 at the rearward end (top) of the tool prevents large mudparticles from reaching the tool seals and inner mechanisms.

FIG. 7A illustrates a schematic longitudinal cross-sectional view of oneembodiment of flow valve 22 in an open position (first position). In anembodiment as shown, valve 22 includes an outer body 41 having an upperportion 45 and a lower portion 44. Upper and lower portions 45, 44 arejoined together by a threaded joint (not shown), and a piston 51slidably disposed in an inner cavity 43 formed inside the outer body 41.Upper portion 45 includes one end 58 with threads 46 to mate with thecorresponding forward end 2B of expandable tubular 2. Lower portion 44includes a support flange 62 with flange fluid passage 50, which allowsfluid flow in and out from inner cavity 43. Outer body 41 also includesone or more fluid passage exits 49 to allow fluid flow out from innercavity 43. In an embodiment, piston 51 is a cylindrical member having apiston inner cavity 52 and one or more piston fluid passages 54 to allowfluid flow from piston inner cavity 52 to fluid passage exits 49. It isto be understood that piston 51 is not limited to the embodimentillustrated in FIG. 7A but instead may include other embodiments havingconfigurations suitable for slidable disposition in inner cavity 43.

As illustrated in FIG. 7A, a flow restriction member 55 is disposedinside piston inner cavity 52. Flow restriction member 55 may be anozzle, an orifice, or any other flow restriction member that may besized to provide a certain force at a given flow rate.

As further illustrated in FIG. 7A, a shear member 61 is disposed inlower portion 44 and engaged in groove 56. Shear member 61 may be a setscrew, a shear pin, a shear ring, or other shear member capable ofcontrolling the position of piston 51 relative to the outer body 41 inthe longitudinal direction. In an embodiment, shear member 61 isdesigned to allow for release of piston 51 at a certain selected forceapplied to piston 51 in the longitudinal direction and then to allowunconstrained movement of piston 51 inside outer body 41. Thecombination of the size of flow restriction member 55 and the size ofshear member 61 may be selected to allow release of piston 51 relativeto outer body 41 at a selected flow rate of operational fluid.

In addition, as shown in FIG. 7A, a bias member 48 is disposed in innercavity 43 of outer body 41. In an embodiment, bias member 48 is disposedin inner cavity 43 of lower portion 44. Bias member 48 may be a spring(i.e., such as a coil spring), an elastomeric member, a solenoidoperated piston, or other member capable of applying a longitudinalforce to piston 51. Bias member 48 engages piston 51 on one end 63 andthe outer body 41 on the other end 64. In some embodiments, bias member48 engages the lower portion 44 on the other end 64. In an embodiment,bias member 48 is adapted to bias piston 51 in an upward position.

As shown in FIG. 7A, a position control member 53 is disposed in groove60. Position control member 53 may be a C-ring, a collet, or otherposition control member capable of locking piston 51 in outer body 41thereby preventing longitudinal movement of piston 51 relative to outerbody 41. When piston 51 is urged into the closed position (i.e., thethird position illustrated in FIG. 7C), position control member 53engages valve body groove 42 and permanently locks piston 51 againstouter body 41. In an embodiment, position control member 53 is adaptedto lock piston 51 in a position preventing longitudinal movement ofpiston 51 in outer body 41.

FIG. 7A also illustrates a sealing member 57 disposed in a sealinggroove 59 located adjacent to piston fluid passages 54. Sealing member57 may be an elastomeric O-ring or any other hydraulic piston sealcapable of providing a hydraulic seal between piston 51 and outer body41.

During tool deployment, valve 22 is in the first open position asillustrated in the embodiment of FIG. 7A and operational fluid is pumpedthrough valve 22 at a selected circulation flow rate. For illustrativepurposes, the selected circulation flow rate is referred to as the firstflow rate. The operational fluid passes through flow restriction member55, piston fluid passage 54, and fluid passage exit 49 out into thewellbore to wash debris away from valve 22 and into the wellboreannulus. The fluid flow creates a pressure drop through the flowrestriction member 55, which results in a force urging the piston 51toward lower portion 44. The shear member 61 exerts a counterforce thatmaintains the piston 51 in the first position maintaining alignment ofpiston fluid passages 54 and fluid passage exits 49, thereby allowingflow of the fluid out of the valve 22. In an embodiment, size of flowrestriction member 55 and size of shear member 61 are selected tomaintain piston 51 in a first position with one or more piston fluidpassages 54 and one or more fluid passage exits 49 aligned at flow ratesbelow or about equal to the first flow rate.

In an embodiment as illustrated in FIG. 7A, after the tool has beendeployed to the desired location, the fluid flow rate is increased to asecond flow rate. The second flow rate develops increased pressure dropin the flow restriction member 55, which results in a force sufficientto shear the shear member 61 thereby releasing the piston 51 andallowing its longitudinal movement inside the outer body 41. Asillustrated in FIG. 7B, piston 51 moves toward the support flange 62into the second position, thereby compressing the bias member 48. In thesecond position of the piston 51, piston fluid passage 54 and fluidpassage exit 49 remain aligned, allowing fluid flow through the valve22, and, therefore, the valve 22 remains open at a second flow rate. Toclose valve 22, the fluid flow rate is gradually decreased to about zeroor near zero allowing the bias member 48 to move piston 51 backwards tothe third position, as illustrated in FIG. 7C. In an embodiment, flowrestriction member 55, shear member 61, and bias member 48 are selectedsuch that at a flow rate equal to about the second flow rate, shearmember 61 releases piston 51 and piston 51 moves longitudinally insideouter body 41 to a second position with one or more piston fluidpassages 54 and one or more fluid passage exits 49 aligned in the secondposition.

In the embodiment as illustrated in FIG. 7C, when piston 51 reaches thethird position, the position control member 53 engages the valve bodygroove 42 thereby locking piston 51 relative to outer body 41 andpreventing longitudinal movement of piston 51 in outer body 41. Positioncontrol member 53 is designed to sustain force greater than the forcegenerated by pressure sufficient for operation of the tool. In the thirdposition, sealing member 57 is located between fluid passage exit 49 inouter body 41 and piston fluid passage 54 in piston 51 therebypreventing fluid flow through valve 22. Valve 22 is permanently closedand hydraulically sealed.

In an embodiment, bias member 48 is selected to generate a minimal forcesufficient for the longitudinal displacement of piston 51 in outer body41. Thus, the displacement of piston 51 to the third position occursonly during very low pressure drop in flow restriction member 55, and,therefore, valve 22 closure takes place at near zero fluid flow rates,practically eliminating the pressure surge.

Certain embodiments of systems, methods and apparatus of this disclosureallow installation and expansion of 3½ inch (8.9 cm)-OD expandabletubular 2 into an open hole through a 4½ inch (11.4 cm)-OD base casing.The following paragraphs discuss procedures for tubular/tool systemmake-up, deployment, tubular expansion, and system retrieval, andadditionally discuss system performance and specifications along withcontingency mitigation procedures.

Systems of this disclosure may be used in many applications, especiallythose in which the pre-expanded launchers of standard, bottom-uphydraulic systems cannot pass through wellbore restrictions. Possibleapplications include open-hole clads, sidetracking, cased-hole patches,and the like.

Systems of this disclosure, including the expansion tool and expandabletubular, can be deployed downhole either on drill pipe (DP) or on coiledtubing (CT), through which the operational fluid (mud) is transmitted tothe tool. The tool is positioned above the expandable tubular, andexpansion takes place in top-down mode. Thus, if necessary, during theexpansion process, the tool can be disconnected from the tubular,retrieved, repaired or replaced with a spare tool, and redeployed in thewell.

One complete expansion process cycle comprises, as its primary steps, anexpansion step or stroke, where the expansion member moves axially toradially expand the expandable tubular, and a resetting stroke, whereone or both anchors is moved axially within the pre-expanded expandabletubular, except in the last few strokes, where the rear anchor movesaxially within an expanded section of expandable tubular. Each expansionstroke involves the application of pressure to the tool and release ofpressure at the end of the stroke. Each resetting stroke involveslowering the tool through the DP or CT. System operating specificationsmay be as shown in Table 2, while Table 3 provides some emergencypressure levels and related events.

TABLE 2 System operating specifications. Range Embodiment 1 Deployment —DP or CT Tubular Weight 8-10 lb/ft (11.9-14.9 kg.m) 9.2 lb/ft (13.7kg/m) Tool Weight 1000-1400 lb (380-530 kg) 1200 lb (545 kg) Tool Length35-55 ft (11-17 m) 45 ft (13.7 m) Expansion Stroke 3-5 ft (92-153 cm) 4ft (122 cm) Max. Tool Run-in — 3.80 in (9.65 cm) OD Min. Pass-Thru —3.81 in (9.68 cm) Restriction Expansion Ratio 20-40% 27% of expandabletubular Max. Dog-Leg 20-50°/100 ft (20-50°/ 50°/100 ft (50°/30.5 m)Severity* 30.5 m) Nominal 50-90 klb_(f) (225-400 60 klb_(f) (270knewtons) Expansion Force knewtons) Maximum — 90 klb_(f) (400 knewtons)Expansion Force Maximum — 7,500 psi (52 MPa) Pressure** Maximum — 250°F.(121° C.) Temperature Push Limit — 100 klb_(f) (445 knewtons) PullLimit — 90 klb_(f) (400 knewtons) *Also referred to as “bend radius” or“build up radius” (BUR) **Without axial load.

TABLE 3 Standard and emergency pressure levels and related events.Differential Pressure, psi (MPa) Event  900 (6) Drive Unit Burst DiskBreaks 1,800 (12) Rear Anchor Shear Pin Breaks 2,300 (16) OperatingExpansion Pressure* 3,800 (26) Casing Lock Shear Pin Breaks forEmergency Release 4,500 (31) Rear Anchor Burst Disk for EmergencyRelease *May vary by as much as 20% due to: anchoring in open hole, wellbore fluid, temperature, friction, tool drag, dog-leg severity andconnector expansion.

Referring to FIG. 2, in certain embodiments of this disclosure, avertical base casing 29 (for example, a 4½ inch (11.4 cm) base casing)has already been installed and cemented in a vertical wellbore, and aliner 30 and deflector or whipstock 31 installed. A forklift and cranemay optionally be used to move the tool into position and attach it toCT or DP as the case may be. For embodiments where 4½ inch (11.4 cm)base casing 29 is in place, slips or dog collars for 3½ inch (11.4 cm)OD pipe and 3.70 inch (9.4 cm) OD tool may be used. For other sizes ofbase casing, the slips and dog collars would be sized accordingly.Typically, a mouse hole (not shown in FIG. 2) would be drilled near themain wellbore for insertion of a positioning tool and shroud to assurethe tool remains vertical. The mouse hole may have an ID of 6 inches(15.2 cm) minimum, and a depth of 40 ft (12.2 m) minimum.

Still referring to FIG. 2, and emphasizing that these dimensions aremerely for purpose of example, to install expandable tubular 2 into adog-leg 32, first a window 34 is milled, having a minimum window length,w, of 3.81 inches (9.68 cm). The build section, 36, may have a minimumID of 4.75 inch (12.07 cm). The Dog-Leg Severity (DLS) in thisembodiment is 45°/100 ft (45°/30.5 m), which is near the maximum forsystems and apparatus of this disclosure. The length of the dog leg rathole, r, is calculated based primarily on the length of dimension “e” inFIG. 2, defined as the distance between the bottom of window 34 tobottom of the unstable shale section. In preparing dog-leg 32, window34, and build section 36, as well as actually installing the tool andexpandable tubular, equipment such as a weight indicator, a pressuremonitoring system, a depth measuring device, a pop-off valve, and themud pumps may be used. These components are readily known by thoseskilled in the art and are therefore not shown, and do not form a partof the present disclosure.

The cladding of expandable tubular 2 occurs within the first expansionstroke right below the window's lower edge. FIG. 2 illustrates onesystem set up in accordance with this disclosure right on the onset ofexpansion, with the expansion member 14 below the lower edge of milledwindow 34. The operator must be aware of the distance “e” between thebottom of the window (BOW) to the bottom of the shale, or equivalently,the minimum ‘true measured depth’ of where the expandable tubular mustsit after expansion minus the depth of the bottom of the milled window.The parameters in FIG. 2 are as follows:

e=distance between bottom of window to end of shale

a=distance between bottom of window to expansion member 14

R=downhole rathole

L=pre-expanded tubular length

s=extra tubular length below bottom of shale

r=installed rathole

t=distance between expansion member 14 and drill pipe connection

α=Exit angle at bottom of shale

w=Window length.

After the distance “e” is determined, Table 4 is used to determine thedownhole rathole length “R” needed after the shale is exited. “L”corresponds to the total length of expandable tubular (liner) beforeexpansion. During drilling of the bend, once shale is exited, drillingmust continue until a rathole “R” is completed.

TABLE 4 Determination of Downhole Rathole e, ft (m) DLS, deg/100 ft L,ft (m) R, ft (m) (deg/30.5 m) 180 (55.0) 207 (63.1) 50 (15) 50 185(56.4) 213 (64.3) 51 (16) 49 190 (57.9) 218 (66.4) 51 (16) 47 195 (59.4)224 (68.3) 52 (16) 46 200 (60.9) 230 (70.1) 53 (16) 45 205 (62.5) 236(71.9) 54 (16) 44 210 (64.0) 241 (73.5) 54 (16) 43 215 (65.5) 247 (75.3)55 (17) 42 220 (67.0) 253 (77.1) 56 (17) 41 225 (68.5) 259 (78.9) 57(17) 40 230 (70.1) 264 (80.5) 57 (17) 39 235 (71.6) 270 (82.3) 58 (18)38 240 (73.1) 276 (84.1) 59 (18) 38 245 (74.6) 282 (86.0) 60 (18) 37 250(76.2) 287 (87.5) 60 (18) 36 255 (77.7) 293 (89.3) 61 (19) 35 260 (79.2)299 (91.1) 62 (19) 35 265 (80.7) 305 (92.9) 63 (20) 34 270 (82.3) 310(94.4) 63 (20) 33 275 (83.8) 316 (96.3) 64 (20) 33 280 (85.3) 322 (98.1)65 (20) 32 285 (86.8) 328 (99.9) 66 (21) 32 290 (88.4) 333 (101) 66 (21)32 295 (89.9) 339 (103) 67 (21) 31 300 (91.4) 345 (105) 68 (21) 30 305(92.9) 351 (107) 69 (21) 30 310 (94.5) 356 (108) 69 (21) 29 315 (96.0)362 (110) 70 (22) 29 320 (97.5) 368 (112) 71 (22) 28 325 (99.0) 374(114) 72 (22) 28 330 (101)  379 (115)  72 (22) 27 335 (102)  385 (117) 73 (23) 27 340 (104)  391 (119)  74 (23) 26 345 (105)  397 (121)  75(23) 26 350 (107)  402 (123)  75 (24) 26 355 (108)  408 ((124) 76 (24)25 360 (110)  414 (126)  77 (24) 25 365 (111)  420 (128)  78 (25) 25 370(113)  425 (130)  78 (25) 24 375 (114)  431 (131)  79 (25) 24 380 (116) 437 (133)  80 (25) 24 385 (117)  443 (135)  81 (26) 23 390 (119)  448(137)  81 (26) 23 395 (120)  454 (138)  82 (26) 23 400 (122)  460 (140) 83 (27) 23 405 (123)  466 (142)  84 (27) 22 410 (125)  471 (144)  84(27) 22 415 (127)  477 (145)  85 (27) 22 420 (128)  483 (147)  86 (27)21 425 (130)  489 (149)  87 (28) 21 430 (131)  494 (151)  87 (28) 21 435(133)  500 (152)  88 (28) 21 440 (134)  506 (154)  89 (28) 20

An operational procedure for making up the embodiment illustrated inFIGS. 1, 2 and 3 may be as follows, and is also illustrated as a processlogic diagram in FIG. 5. In this embodiment 500, at the surface, tubularbundles are unloaded from trucks using slings to prevent scratching andbanging of tubulars (box 502). A check should be made that the surfacerat hole is 40 ft (12.2 m) deep minimum (box 504). A rated sling maythen be wrapped around the collar of the tool shroud (box 506). Thecombined weight of tool plus shroud is less than 2,100 lb_(f) (9.3knewtons). Lift the shroud with tool vertical and insert in surface rathole. Leave there until tool is ready to be deployed (box 508). Unclampthe tubular bundles and check for any damage to the DP (or CT if used),and check every connection for damage before make up (box 510). Cleanthe hole where tubular will be expanded at flow rate as specified by anExpansion Job Sheet (box 512). Attach a lifting sub to a box connectionof the pup-joint with the nozzle and lift. Weight may rest on thenozzle. Insert pup-joint into well and clamp so that connector is 3-4 ft(91-122 cm) above well head (box 514). Unscrew lifting sub, and installstabbing guide onto exposed box connection (box 516). Select the nextjoint according to Expansion Job Sheet (box 518). Leave the Range-3joints (35-37 ft) (10-10.7 m) to the end. Replace box protector withlifting sub, and lift joint and position it above the joint inserted inwell (box 520). Remove thread protector from the pin. Stab-in andmake-up connector by hand using a strap wrench (box 522). In certainembodiments, pipe dope or grease is not used (in these embodimentsconnectors come ready for make-up). Remove stabbing guide; torque theconnector to 600 ft-lb (83 kg-m) by hand (box 524). Unclamp and lowertubulars in well until lifting sub is 3-4 ft (91-122 cm) above well head(box 526). Clamp/secure tubular in well head (box 528). Continue untilthe desired length of tubular is made-up according to the Expansion JobSheet (box 530).

The make-up may proceed as follows. Lift the 46-foot (14 m)-long toolout of protective shroud, remove the pin thread protector on tubular.Position the lower end of the tool above the box of the tubular insertedin well. Lower expansion tool and complete the following checks: (1)check for damage or wear on the welded strips on pipe next to theexpansion member; (2) check the distance of exposed shaft between therear anchor and drive unit (this should be no more than ½ in (1.3 cm));(3) check if rear shear screw is fully screwed into rear anchor; (4)check if all rear anchor bows are in place and with two socket screwsfully screwed per bow; (5) check if rear anchor pads are retracted.

Once the above checks are completed, clamp the expansion tool fluidfilter above the rear anchor and rest the tool with liner (expandabletubular) on the well. The maximum weight of the hanging equipment atthis point should be no more than 7,000 lb_(f) (31 kilonewtons). Removelift hook and unscrew lifting sub and eye bolt from the tool. Connectpin connector of next string to the tool's 2⅜ inch (6 cm) P.A.C. box (atype of thread used on thru-tubing tools). Different crossovers may haveto be procured depending on what DP is used. Apply the recommendedtorque.

Deployment for embodiments having an end cap (and no flow valve) issimilar. The DP or CT is lowered. The tool string is set so that theexpansion member (cone) is a distance of about 5 ft (1.5 m) below thebottom of the window (see FIG. 2). The distance between the expansionmember (cone) and the end of the fluid filter (end of tool) is about 33ft (10 m).

Expansion of the expandable tubular or liner may proceed according tothe following non-limiting procedure, as illustrated in FIG. 6. Set thesurface pop-off valve at 3500 psi (24 MPa) (box 602). Start increasingthe system pressure with the smallest GPM the pump can provide. Pressurewill start increasing while the following sequence of events takes place(box 604). Drive unit shear disk breaks at 900 psi (6 MPa) (box 606).Rear anchor shear screw breaks at 1800 psi (12 MPa) (box 608). Theexpansion pressure during the first stroke should be within the2,200-2,800 psi (15-19 MPa) range (box 610). This is larger than theuniform expansion pressure due to the anchoring mechanism during thefirst stroke. During every pressure stroke, the shortening of the liner(expandable tubular) due to expansion will be seen at surface as adecrease in the weight indicator's reading by about 8,000 lb_(f) (36knewtons) in DP, and 3,000 lb_(f) (13 knewtons) in CT. This decreaseoccurs gradually throughout each expansion stroke. After the pop-offvalve releases pressure, lower the DP or CT at a speed no faster than 4ft/min (122 cm/min) for about 4 ft. (122 cm) until the weight indicatorshows approximately 5,000 lbf (22 knewtons) of weight decrease (box612). Then start increasing the system pressure with the smallest GPMthe pump can provide (box 614). Pressure should come up to steadyexpansion pressure of approximately 2,200 psi (15 MPa) for the length ofthe stroke. At the end of the stroke pressure will rise which will againtrigger the pop-off valve (box 616). Continue repeating these stepsuntil all the expandable tubular length has expanded. Monitor the lengthof expanded tubular by the length of the lowered DP or CT, accountingfor the tubular shrinkage due to expansion. Also, monitor the number ofexpanded connectors by their pressure variation signature (box 618). UseExpansion Job Sheet. In the second to last resetting stroke, theexpansion tool should remove valve 22 from the expandable tubular. Thisrequires approximately 500 lb_(f) (22 knewtons), which should be seen onthe weight indicator. After the expansion member exits the forward endof the expandable tubular, the pressure drops and then sharply risestriggering the pop-off valve after last stroke gets consumed. To ensurethat expansion has been completed, lower the DP or CT for more than 4 ft(122 cm).

Retrieval of the expansion tool may proceed according to the followingnon-limiting procedure. After completing expansion, pull the DP or CTall the way out through the expanded pipe, open hole and productioncasing. The load to pop the expansion member off the mouth of theexpanded liner should be no greater than 13,000-15,000 lb_(f) (56-65knewtons). This should be seen as an equivalent increase in the weightindicator. In case the pull out load at any point increases by as muchas 30,000 lb_(f) (133 knewtons), stop pulling, increase pressure to4,500 psi (31 MPa) to shear the rear anchor for permanent closure.Continue pulling the string out. Clamp the tool on well head through thefluid filter. Disconnect DP or CT pin connection from the expansiontool. Install lifting sub with eye bolt on tool and retrieve from hole.Insert tool on its respective shroud still in the rat hole. Tie the eyebolt on the tool to collars on the shroud. Lift tool shroud and loadback into truck for take back.

The risk assessment table, Table 5, contains a non-limiting list of 14possible scenarios that could decrease the degree of success of aspecific expansion job in different degrees. The legend used to quantifyeach risk was as follows:

Likelihood, L: Probability of risk to occur

1=Improbable

2=Unlikely

3=Possible

4=Likely

5=Probable

Severity, S: Impact of risk on Job economics and HSE

1=Low: Loss of a few thousand dollars or a few hours, no HSE risk

2=Med-Low: Loss of a few tens of thousands of dollars or tens of hours,minimal HSE risk

3=Medium: Loss of 10% of well cost or several days, medium HSE risk

4=Med-high: Loss of 50% of well cost or several weeks, major HSE risk

5=High: Total scrap of well, HSE fatality.

Exposure, E: L×S, ranges from 1 to 25, with 1 being a “good” result and25 a “bad” result.

TABLE 5 Risk mitigation table. No. Risk Description Stage L S EMitigation Plan 1 Damaged Make up 3 1 3 Carry spare joints connectors/Joints do not make up 2 Cone stuck in Deploy. 3 1 3 Clean base casing IDbase casing ID 3 Nozzle does not Deploy. 3 1 3 Different RIHspeeds/re-mill past thru window window 4 Loosing the liner Deploy. 2 2 4Push it to position/pick up with Front Anchor 5 Loosing system Deploy. 13 3 Fishing operation and liner 6 Cone stuck on 1st Deploy. 3 2 6Pressure up to 3800 psi (26 MPa) stroke and pipe to unlock tool-linerthru Casing cladded Lock/use back up tool/fish pipe out 7 Cannot expandExp. 3 2 6 Use back up tool/fish pipe out mid-liner 8 Expansion Exp. 2 36 Use back up tool/fish pipe out pressure drops dramatically 9 Cannotexpand Exp. 3 2 6 Use back up tool/stronger Rear three last Anchor burstdisk/cut casing Strokes 10 Need well control Exp. 2 2 4 Pressurize to4,500 psi (31 MPa) to open tool thru Rear Anchor. 11 Cannot pull toolRetrieval 3 1 3 Pull 20-40 klbf (90-180 knewtons) thru end of liner toshear Al nozzle 12 Cannot pull tool Retrieval 3 2 6 Pressurize to 4,500psi (31 MPa) thru expanded to burst rear anchor disk for liner/basecasing retraction. 13 Cannot pull tool Retrieval 2 1 2 Pressurize to4,500 psi (31 MPa) thru open hole and circulate to clean debris. sectionbelow window. 14 Tool did not catch Retrieval 3 1 3 Drill out on nexttrip nozzle

In embodiments where expansion cannot be completed, the semi-expandedliner would have to be fished out of the well. A fishing mechanism couldengage either on the pre- or post-expanded ID of the expandable tubular.In one embodiment their dimensions are as follows:

Pre-expanded tubular dimensions: ID: 2.992 inch (7.599 cm),

OD: 3.510 inch (8.915 cm)

Post-expanded tubular dimensions: ID: 3.81 inch (9.68 cm),

OD: 4.27 inch (10.8 cm).

Due to the tandem open hole anchors (not illustrated) that fix thecasing to the formation during the first stroke, in this example thesemi-expanded casing would need a maximum of 70,000 lbf (311 knewtons)of pull to start sliding the liner out of hole.

A fishing tool that might be used in the above example if the expansiontool is lost in the well is illustrated in cross-section in FIG. 4,which contains all the dimensions of the connection on which breakagemay occur.

The skilled operator or designer will determine which system, method,and apparatus within this disclosure is best suited for a particularwell and formation to achieve the highest efficiency, safety, andenvironmentally sound well intervention without undue experimentation.

EXAMPLES Expandable Liner Example Trial 1

RIH with 408 feet of un-expanded 3.5 inch liner, through maximum Dog LegSeverity (DLS) of 37°/100 feet. Tool expanded 46 inches of liner, butnot all of the liner; however, it was learned that the tool did notfail, pressure readings at the surface could readily be understood, andthe upper anchor sub-system needed to be improved as describedhereinafter. The un-expanded liner was successfully fished, and thewell-bore was saved.

Expandable Liner Example Trial 2

Applied lessons learned from Example Trial 1. Reconfigured the pistonsystem within the expansion tool to stroke to 48 inches. Added a thirdcladding to increase support for upper (rear) anchor (see FIG. 8,claddings are noted at 70, 72, and 74, with 74 being the additionalcladding). RIH with 447 feet of un-expanded 3.5 inch liner, throughmaximum DLS of 31°/100 feet. Pumped through large diameter iron, readingpressures at the stand pipe. Experienced some tight spots whileexpanding, but managed to get the cone of the tool down. Lost 5 slipbodies at the end of expansion process. RIH with a 3.75 inch “crayola”mill to bottom. Found that liner had slid downward, expansion was notcomplete (lacked about 14 feet).

Lessons learned: fluid used for the expansion process (mud), while notnecessary to be ultra-pure, cannot comprise any large-scale debris,cedar fibers or other similar solids that may be retained by the filteror other system components and cause pressure to increase severely.

From the foregoing detailed description of specific embodiments, itshould be apparent that patentable methods, systems and apparatus havebeen described. Although specific embodiments of the disclosure havebeen described herein in some detail, this has been done solely for thepurposes of describing various features and aspects of the methods,systems and apparatus, and is not intended to be limiting with respectto the scope of the methods, systems and apparatus. It is contemplatedthat various substitutions, alterations, and/or modifications, includingbut not limited to those implementation variations which may have beensuggested herein, may be made to the described embodiments withoutdeparting from the scope of the appended claims.

1. A tubular member radial expansion apparatus comprising: a) a supportmember having a forward end and a rearward end; b) a drive unit and anexpansion member disposed on the support member providing force forpropelling the expansion member through and radially expanding anexpandable tubular, the drive unit disposed rearward of the expansionmember; c) front and rear anchors disposed on the support member forengaging the expandable tubular's ID to provide reaction forces topropagate the expansion member through the expandable tubular, the rearanchor positioned behind the drive unit and providing its reaction forceafter the front anchor has exited the expandable tubular; d) a casinglock disposed on the support member and positioned between the expansionmember and the front anchor, releasably securing the expandable tubularto the support member during running-in-hole; and e) a valve attached toa forward end of the expandable tubular.
 2. The apparatus of claim 1wherein the support member defines one or more internal fluid passages.3. The apparatus of claim 2 comprising a flow valve fluidly connected tothe forward end of the support member and at least one of the internalfluid passages.
 4. The apparatus of claim 1 comprising a fluid filterfluidly connected to the support member and at least one of the internalfluid passages and positioned at the rearward end of the support memberpreventing large mud particles from reaching the tool seals and innermechanisms.
 5. The apparatus of claim 1 wherein the support member istubular.
 6. The apparatus of claim 1 wherein the expansion member isconical, having an outer surface engaging an inner surface of theexpandable tubular, the outer surface having a diameter which decreasesfrom a forward end to a rearward end of the expansion member.
 7. Theapparatus of claim 1 comprising an end cap attached to the forward endof the support member.
 8. The apparatus of claim 1 wherein theexpandable tubular is metallic and has an expansion ratio ranging fromabout 20 to about 40 percent.
 9. The apparatus of claim 8 able toachieve a bend radius ranging from 20-50°/100 ft (20-50°/30.5 m).
 10. Atubular member radial expansion system comprising: a) a deploymentcomponent; and b) a tubular member radial expansion apparatuscomprising: i) a support member having a forward end and a rearward end;ii) a drive unit and an expansion member disposed on the support memberproviding force for propelling the expansion member through and radiallyexpanding an expandable tubular, the drive unit disposed rearward of theexpansion member; iii) front and rear anchors disposed on the supportmember for engaging the expandable tubular's ID to provide reactionforces to propagate the expansion member through the expandable tubular,the rear anchor positioned behind the drive unit and providing itsreaction force after the front anchor has exited the expandable tubular;iv) a casing lock disposed on the support member and positioned betweenthe expansion member and the front anchor, releasably securing theexpandable tubular to the support member during running-in-hole; and v)a valve attached to a forward end of the expandable tubular.
 11. Thesystem of claim 10 wherein the deployment component is selected fromcoiled tubing and drill pipe.
 12. The system of claim 10 wherein thesupport member defines one or more internal fluid passages.
 13. Thesystem of claim 10 wherein the expansion member is conical, having anouter surface engaging an inner surface of the expandable tubular, theouter surface having a diameter which decreases from a forward end to arearward end of the expansion member.
 14. The system of claim 10 whereinthe expandable tubular is metallic and has an expansion ratio rangingfrom about 20 to about 40 percent.
 15. The system of claim 14 able toachieve a bend radius ranging from about 20 to about 50°/100 ft(20-50°/30.5 m).
 16. A method of expanding a tubular member, comprising:a) deploying an expandable tubular and an expansion tool into awellbore, the expandable tubular secured to a support member of theexpansion tool, the support member having a forward end and a rearwardend, the rearward end attached to a deployment component communicatingwith the surface; and b) performing an intervention operation on thewellbore comprising using the expansion tool to expand the expandabletubular and so complete the wellbore, wherein the expansion tool furthercomprises a drive unit and an expansion member disposed on the supportmember providing force for propelling the expansion member through theexpandable tubular axially from rear to forward and radially expandingthe expandable tubular, the drive unit disposed rearward of theexpansion member; front and rear anchors disposed on the support memberfor engaging the expandable tubular's ID to provide reaction forces topropagate the expansion member through the expandable tubular, the rearanchor positioned behind the drive unit and providing its reaction forceafter the front anchor has exited the expandable tubular.
 17. The methodof claim 16 wherein the deploying proceeds by using deploymentcomponents selected from coiled tubing and drill pipe.
 18. The method ofclaim 16 wherein the well intervention operation is selected fromopen-hole clads, sidetracking, and cased-hole patches.
 19. The method ofclaim 16 comprising radially expanding the expandable tubular to anexpansion ratio ranging from about 20 to about 40 percent.
 20. Themethod of claim 19 comprising deploying the expansion tool andexpandable tubular into a non-horizontal wellbore having a bend radiusranging from about 20 to about 50°/100 ft (20-50°/30.5 m).